Annular fluids or packer fluids are liquids which are pumped into and reside in an annular space between a casing and a tubing wall, between adjacent concentric strings of pipe extending into a wellbore (casing annulus) or into the bore of a cased wellbore.
In the completion of oil and gas wells, it is currently the practice to place aqueous or non-aqueous hydrocarbon based fluids, known as packer fluids, into a casing annulus above a packer, specifically where the packer has been set to isolate production fluid from the casing annulus. Packer fluids, introduced into the casing annulus, fill the annular column to surface.
Packer fluids are used to provide both pressure stability and thermal protection to the casing annulus of production oil and gas wells as well as in injection wells. Further, packer fluids act to maintain casing and tubular integrity. The main function of a packer fluid related to pressure stabilization is to provide hydrostatic pressure in order to equalize pressure relative to the formation, to lower pressures across sealing elements or packers; or to limit differential pressure acting on the well bore, casing and production tubing to prevent collapse of the wellbore.
Typically, packer fluids are used extensively in areas which are subject to low ambient temperatures or which have significant frost penetration through which the wellbore extends. If fluids within the wellbore freeze as a result of contact with the frost layer, compressive or tension loads may be imposed, which can be sufficient to fracture the well casing and/or associated equipment such as wellhead valving and the like. Further, if sufficient heat is transferred out of the production fluids to the frost penetration layer, hydrate crystals can form within the production fluid, which can freeze together and block the bore of the string of production tubing.
It is well known, and in some cases a regulated requirement, to add a thermal capping fluid, such as diesel which is resistant to freezing and which is lighter than the in situ wellbore fluids and therefore locates adjacent the frost penetration layer at surface. Thus, thermal insulation results in the wellbore or wellbore annulus at the frost penetration layer to minimize transfer of heat from the warm production fluids within the tubing string and the frost penetration layer.
Capping fluid is commonly added on top of aqueous packer fluids which have been treated with chemical additives. In operation, chemical additives are typically added to the water or brine in a rig tank, tank or tank truck prior to being displaced downhole in the casing annulus. Diesel is then added as a layer on top of the packer fluid column to fill the annular space at the level of the frost penetration. Alternatively, additives may be added to aqueous fluids already in the annulus prior to capping with diesel. The effect of the additives can be reduced if the additives do not adequately disperse in the packer fluid and further, dispersion into the diesel layer may be enhanced.
When capping fluids such as diesel or other environmentally unfriendly hydrocarbons are used as freeze protection, they are typically the last fluids placed in the casing annulus and characteristically migrate to the top of the wellbore. Accordingly, any spillage which may occur as a result of overfilling will include capping fluid. Such accidental release may occur for a number of other reasons including: as a result of thermal expansion of fluids within the wellbore and as a result of conduction, especially on wells that have been shut in and thermally heated; during higher temperature service or where the casing may have to be opened to intervene on a well; or during packer/wellbore isolation tests. Significant damage to the surrounding environment may occur as a result of such spills. Further, the already highly toxic capping fluid may be made more toxic due to dispersion of additives from the aqueous layer upwardly into the diesel layer. Handling of these conventional capping fluids present significant risk to personnel who may be exposed either through direct contact causing absorption through the skin or breathing of toxic fumes.
Most often, during normal operation, the wellbore is filled with fluid which is typically an aqueous fluid, such as fresh water or produced brine. Fresh water or produced brine are used as they are readily available at the wellsite, however aqueous fluids are considered corrosive due to their inherent composition. As a result of brine content, dissolved gases or the presence of microbiological agents, aqueous fluids can pose a significant risk to carbon steel equipment, such as conventional tubulars and casing, with which they come into contact.
As previously introduced, it is well known to add chemical additives in various concentrations to reduce, or eliminate any or all of the above mentioned types of activity. Additives of various types and chemistry are currently added to aqueous packer fluids. The purpose of these additives is to address the problems that can occur from the use of aqueous fluids in the annular space between the casing and the production tubing in completed oil and gas wells. Some of these additives include aqueous corrosion inhibitors, scale inhibitors, salt inhibitors, oxygen scavengers, non-emulsifiers and biocides. The additives may be added to either fresh or produced waters as well as to some non-aqueous hydrocarbon-based packer fluids, which may contain residual amounts of water. Use of chemicals prolongs the mechanical integrity of cased wellbores including production tubing strings and the casing annulus.
Typically fluids are selected and used for convenience of use, economics, availability, and industry acceptance. Such fluids, except in the case of untreated fresh H2O, can present significant ecological challenges and possibly affect wellbore integrity depending upon the additives used. Many additives, though able to effectively negate corrosion and bacterial problems, act to render the prior art packer fluids more environmentally unfriendly than they were as merely saturated brine.
Others have attempted to improve environmental acceptability of packer fluids. U.S. Pat. No. 5,607,901 to Toups Jr. et al. teaches a thixotropic insulating fluid comprising an environmentally acceptable non-aqueous, continuous phase fluid which is non-corrosive. The mixture contains a polar organic solvent, a hydrophilic clay and a liquid non-aqueous, non-corrosive liquid which must be combined and mixed at the wellsite for a significant period prior to addition to the wellbore annulus. Toups Jr. et al. are concerned only with providing thermal insulation to the wellbore and do not contemplate additives to combat corrosion and the like. Applicant believes that any additives added to the fluid of Toups et al. would be dispersed throughout the fluid and to the surface and would therefore render the fluid environmentally unacceptable and hazardous to personnel.
Ideally, liquids used as packer fluids should have sufficient specific gravity to enable pressure stabilization of the producing formation, be solids free, resistant to viscosity changes over periods of time, and compatible with both wellbore and completion components and materials. Further, the fluid should be environmentally acceptable so as to minimize damage during use. The fluid should be economical and easily handled to effect cost savings in rig time and associated services, as well as chemical additive costs.